Method of enhancing drilling fluid performance

ABSTRACT

The present invention relates to methods of drilling a wellbore wherein a drill-in fluid is foamed at the drill tool. A method in accordance with the present invention comprises providing a drill-in fluid comprising an aqueous fluid, a foaming agent, a foam stabilizer, a gas generating chemical and an encapsulated activator; introducing the drill-in fluid downhole into a drill string connected to a drill tool; and allowing the drill-in fluid to exit the drill tool where, upon exiting the drill tool, the encapsulated activator is de-capsulated sufficiently to react with the gas generating chemical such that a gas is generated within the drill-in fluid and thus foams the drill-in fluid.

BACKGROUND OF THE INVENTION

1. Field of the Invention

The present invention relates to methods of enhancing drilling fluid performance. More particularly, the present invention relates to enhancing drilling fluid performance where foam is used as at least part of the drilling fluid.

2. Description of Related Art

Hydrocarbons, such as oil and gas, may be recovered from various types of subsurface geological formations. Such formations typically consist of a porous layer, such as limestone and sands, overlaid by a nonporous layer. Hydrocarbons cannot rise through the nonporous layer, and thus, the porous layer forms a reservoir in which hydrocarbons are able to collect. A well is drilled through the earth until the hydrocarbon bearing formation is reached. Hydrocarbons then are able to flow from the porous formation into the well.

In conventional drilling processes, a drill bit is attached to a series of pipe sections or coiled drilling tubing referred to as the drill string. The drill string terminates in a drill tool, which cuts a borehole through the different formations. The drill string is gradually lengthened as the drill tool cuts the borehole. Additionally, drilling in the borehole is also utilized in well completion and production operations, such as drilling out packers utilized during well casing operations and workover operations.

As a wellbore is drilled, the production of hydrocarbons from hydrocarbon producing formations must be controlled until the well is completed and the necessary production equipment has been installed. The most common way of controlling production during the drilling process is to circulate a drilling fluid. Typically, the drilling fluid is pumped down the drill string, through the drill tool, and into the wellbore. The hydrostatic pressure of the drilling fluid in the wellbore relative to the hydrostatic pressure of hydrocarbons in the formation is adjusted by varying the density of the drilling fluid, thereby controlling the flow of hydrocarbons from the formation.

In addition to controlling hydrostatic pressure, drilling fluids are used for a variety of other purposes. The drilling fluid also helps stabilize uncased portions of the wellbore and prevents it from caving in. Large quantities of cuttings are generated during drilling. As it is re-circulated back up the wellbore, the drilling fluid also carries cuttings away from the drill tool and out of the wellbore. Also when rotary drill tools or drill bits are used, a tremendous amount of heat can be generated as the drill string is rotated and the bit cuts through the earth. The drilling fluid serves to lubricate and cool the drill bit.

Traditionally, drilling fluids have most commonly been high-density dispersions of fine, inorganic solids, such as clay and barite, in an aqueous liquid or hydrocarbon liquid. These drilling fluids have traditionally been called drilling mud and the drilling has been conducted in an overbalanced condition; that is, the hydrostatic pressure of drilling fluid in the wellbore exceeds the pressure of hydrocarbons in the formation. Hydrocarbons, therefore, are prevented from flowing into the wellbore. This avoids the risk that the well will blow-out and damage the environment and drilling equipment or injure those working on the drilling rig.

A major consequence of overbalanced drilling operations is that drilling fluid can flow from the wellbore into the formation. That flow of fluid at relatively low levels is referred to as seepage and, at higher levels, as lost circulation. Seepage, and especially lost circulation, in turn may have several deleterious and costly effects. First, any drilling fluid that flows into the formation must be replaced in order to maintain circulation of fluid through the well. The amount and cost of drilling fluid required to drill the well, therefore, is increased.

Second, seepage and lost circulation of drilling fluid can carry with it the cuttings and many of the other components in the drilling fluid, which can decrease the permeability of the formation. Thus, it becomes more difficult for oil to flow from the formation once drilling is completed and production is started. Decreased permeability also may require acidizing or fracturing the hydrocarbon bearing formation to enhance production from the formation, which will further increases costs.

The problems associated with seepage and lost circulation may be addressed by adjusting the density of the drilling mud. The density of the drilling mud may be controlled by the amount of solids added and, therefore, adjusted to balance the hydrostatic pressures at the interface between the wellbore and the formation. Seepage and lost circulation and their attendant problems also may be addressed by the formation of a filter cake on the wall of the wellbore or by the addition of filtration control and seepage control additives designed to physically impede the flow of fluid into the wellbore.

While drilling mud is suitable for use in a wide variety of hydrocarbon bearing formations, in many formations the hydrostatic pressure of hydrocarbons in the formation is relatively low and many drilling muds are simply too heavy for low pressure formations. They can significantly overbalance the well, allowing excessive amounts of drilling fluid to flow into the formation. The problems caused by seepage and lost circulation are exacerbated when a low pressure formation is also relatively fragile, such as fractured limestone formations. Fragile formations may be excessively fractured by the hydrostatic pressure of drilling fluid flowing into the formation and carry even more materials into the formation that will diminish its permeability. Seepage and lost circulation materials, in particular, if they are carried into the formation, can cause extensive damage to the formation.

Accordingly, it is often preferable to drill through formations that are highly permeable, that have low pressures, or that are fragile in a near balanced or underbalanced state. That is, the hydrostatic pressure of the fluid in the wellbore will be approximately equal to or less than the hydrostatic pressure of the formation, and various lower density drilling fluids have been developed for such purposes. Such drilling fluids, known as drill-in fluids, are specially designed to minimize formation damage when drilling into reservoir sections. Drill-in fluids may be an aqueous brine containing only selected solids of appropriate particle size ranges (salt crystals or calcium carbonate) and polymers. Generally, additives in drill-in fluids have been limited to ones essential for filtration control and cuttings carrying. Accordingly, these drill-in fluids have included a bridging agent designed to form a filter cake, which is external to the formation and which can easily be removed during the completion phase.

Such drill-in fluids may still be too heavy for use in extremely low-pressure, fragile formations without substantial losses. Lower densities have been achieved by using foamed drill-in fluids. They typically comprise a surfactant solution with gas dispersed therein. The surfactant acts to stabilize the gas dispersion. For environmental reasons, aqueous systems are preferred, and they typically include a polymer to improve the rheological and thixotropic properties of the foam.

In general, such foamed drill-in fluids perform quite well in drilling operations and offer several advantages over traditional suspended solids drilling fluids. For example, the density of the foam may be controlled relatively easily by adjusting the gas injected into the foam. Also, the ability of foamed drill-in fluids to carry cuttings away from a drilling bit is much greater than that of liquid drilling fluids. More effective removal of cuttings allows drilling to proceed at a faster pace, thereby reducing the time and expense of drilling. Moreover, when used at near balanced or underbalanced conditions, foamed drill-in fluids can effectively prevent damage to even highly fragile, highly permeable formations.

Foamed drill-in fluids are prepared by mixing a liquid phase, such as a polymer-surfactant solution, and a gas phase, such as nitrogen. Typically, this has been done by high velocity mixing of the phases or by injecting gas into the liquid phase through a small orifice. Most commonly, the foam is generated at the surface and then pumped into the wellbore. It also has been suggested that drill-in fluids may be foamed by pumping separate liquid and gas streams through a drill string to a downhole foam generator.

Both generating foam at the surface and below the surface, by use of separate streams, entail significant cost. The foamed drill-in fluids require a source of gas such as nitrogen and various additional equipment that are not needed in conventional liquid circulation systems. For example, if liquid nitrogen is used, special tanks and equipment for cryogenically storing and handling the liquid nitrogen are required. Foam circulation systems also may include compressors, storage tanks, air pumps, foam generators, and other equipment beyond that commonly employed for circulating liquids. Moreover, unlike many other drilling fluids which are hydraulic, foamed drill-in fluids are pneumatic. Special pneumatic pumps and control heads may have to be used to pump or otherwise control the foam in the wellbore. Thus, systems for preparing and circulating foamed drill-in fluids are relatively costly and require more maintenance, control, and logistical support than those required for more traditional suspended solids drilling fluids.

Such problems are exacerbated in offshore drilling operations where maintenance and logistical support are more difficult and costly. Space also is at a premium in offshore operations. On land, there usually is adequate space for additional equipment. Offshore, however, valuable space on the drilling rig deck is required, or it may be necessary to provide a barge or support boat to accommodate a foam circulation system. That can add considerable cost to the drilling operation.

It is therefore desirable to enhance the performance of foamed drill-in fluids and reduce the cost of the application of foamed drill-in fluids.

SUMMARY OF THEN INVENTION

The present invention relates to methods of generating gas downhole during drilling operations so as to produce a foamed drill-in fluid downhole between the drill tool and the wellbore.

In one embodiment, the present invention provides a method of drilling in a wellbore comprising the steps of providing a drill-in fluid comprising an aqueous fluid, a foaming agent, a foam stabilizer, a gas generating chemical and an encapsulated activator; introducing the drill-in fluid downhole into a drill string connected to a drill tool wherein both the gas generating chemical and the encapsulated activator are admixed into the drill-in fluid prior to introduction into the drill string; and allowing the drill-in fluid to exit the drill tool where, upon exiting the drill tool, the encapsulated activator is de-capsulated sufficiently to react with the gas generating chemical such that a gas is generated within the drill-in fluid and thus foams the drill-in fluid.

In another embodiment, the present invention provides a method of drilling in a wellbore comprising the steps of providing a drill-in fluid consisting essentially of an aqueous fluid, a foaming agent, a foam stabilizer, a gas generating chemical and an encapsulated activator; introducing the drill-in fluid downhole into a drill string connected to a drill tool wherein the aqueous fluid, the foaming agent, the foam stabilizer, the gas generating chemical and the encapsulated activator are all admixed into the drill-in fluid prior to introduction into the drill string; and allowing the drill-in fluid to exit the drill tool where, upon exiting the drill tool, the encapsulated activator is de-capsulated sufficiently to react with the gas generating chemical such that a gas is generated within the drill-in fluid and thus foams the drill-in fluid.

DESCRIPTION OF THE PREFERRED EMBODIMENTS

The present invention provides improved methods of generating gas in and foaming a drill-in fluid upon the drill-in fluid's exiting the drill tool; that is, while the drill-in fluids are passing from the interior to the exterior of the drill tool and while the drill-in fluid is in the region between the drill tool and the borehole where drilling of the formation is occurring. In accordance with the invention, the drill-in fluid comprises an aqueous fluid, a foaming agent, a foam stabilizer, a gas generating chemical and an encapsulated activator. Additionally, the drill-in fluid can comprise a water soluble viscosifier, a fluid loss control additive and a bridging agent. The viscosifier, fluid loss control additive and bridging agent are optional and depend upon the specific application; however, it is a distinct advantage of the current invention that the drill-in fluid described herein will have a reduced need for fluid loss control additives, viscosifying agents and/or bridging agents. Accordingly, for many applications, the drill-in fluid will not contain these components and, indeed, the inventive drilling process will be carried out without the use of viscosifiers, fluid loss control additives and bridging agents other than as those functions are carried out by one or more of the aqueous fluid, foaming agent, foam stabilizer, gas generating chemical and an encapsulated activator as present in the foamed drilling fluid. Thus, in one embodiment of the invention, the drill-in fluid consists essentially of an aqueous fluid, a foaming agent, a foam stabilizer, a gas generating chemical and an encapsulated activator. It should be understood that for the components of the drill-in fluid, the use of singular forms of “a,” “an” and “the” include plurals and thus encompass one or more of the listed components.

The aqueous fluid of the drill-in fluid can be any aqueous liquid capable of forming a solution with the other components of the drill-in fluid. The term “solution” as used herein, encompasses dispersions, emulsions, or any other substantially homogeneous mixture, as well as true solutions. The solvent preferably is either fresh water or an aqueous brine. Generally, the aqueous liquid can make up from about 80 percent to about 98 percent of the drill-in fluid by weight.

The gas generating chemicals useful in accordance with this invention will react with the activator in aqueous solutions to generate a gas, which may be selected from the group consisting of carbon dioxide, oxygen, sulfur dioxide, nitrogen, nitrogen dioxide, ammonia, and mixtures thereof, or consisting of any subgroup of the foregoing. Generally, gas generating chemicals that react to generate primarily carbon dioxide or nitrogen are preferred. While the gas generating chemicals will generally produce one primary gas, they can also produce one or more secondary gases. For example, those that primarily generate nitrogen can also generate small amounts of ammonia depending on the chemical structure of the gas generating chemical and the activator or activating agent. Thus, when the nitrogen gas generating chemical molecule contains amide groups, additional ammonia, carbon dioxide (an acidic gas), and carbon monoxide may be produced.

In order to cause the gas generating chemicals to generate gases, one or more encapsulated activators are combined with the drill-in fluid containing one or more gas generating chemicals. The encapsulated activator can have a pre-selected release time or temperature such that the activator becomes de-capsulated after a pre-selected amount of time in the drill-in fluid or after the drill-in fluid reaches a pre-selected temperature; however, it is preferred that the encapsulated activator have a release associated with the high shear conditions at the drill tool. Accordingly, in one embodiment, the encapsulation material releases or de-capsulates the activator when the drill-in fluid undergoes the shear conditions at the drill tool and/or in the region between the drill tool and borehole. The conditions in these regions are what is known as high shear conditions and will be greater shear conditions than experienced by the drill-in fluid prior to entering the drill tool from the drill string. The release or de-capsulation should be sufficient so that enough activator reacts with the gas generating chemical so as to generate gas sufficient to foam the drill-in fluid to a predetermined level or density. In this manner, the encapsulated activator can be released without relying on time or temperature release encapsulating means.

Generally and as described below, the gas generating chemicals will be a reducing agent and the encapsulated activator will be an oxidizing agent. However, it is within the scope of the invention for the gas generating chemical to be the oxidizing agent and the encapsulated activator to be the reducing agent. Thus, while the compounds below are listed as either a gas generating chemical or as an encapsulated activator, it should be understood that this is how they will typically be utilized in the invention but they can serve as either as long as there is both a reducing agent and an oxidizing agent; that is, a reducing compound can serve as the encapsulated activator as long as an oxidizing agent serves as the gas generating chemical. In this regard, because solid compounds can be easier to encapsulate, generally a solid compound will be chosen as the encapsulated activator.

Nitrogen gas generating chemicals which can be utilized in accordance with the methods of the present invention include, but are not limited to, compounds containing hydrazine or azo groups, for example, hydrazine, azodicarbonamide, azobis (isobutyronitrile), p-toluene sulfonyl hydrazide, p-toluene sulfonyl semicarbazide, carbohydrazide, p-p′ oxybis (benzenesulfonylhydrazide) and mixtures thereof. Additional examples of nitrogen gas generating chemicals which do not contain hydrazine or azo groups and which are also useful in the present invention include, but are not limited to, ammonium salts of organic or inorganic acids, hydroxylamine sulfate, carbamide and mixtures thereof. Of these, azodicarbonamide or carbohydrazide are preferred.

The generation of gas from the nitrogen gas generating chemicals depends on the structure of the gas generating chemicals. When the chemical contains an azo group containing two nitrogens connected by a double bond as in azodicarbonamide, the gas generation is caused either thermally or by reaction with alkaline reagents. The reactions with the azocarbonamide generate ammonia gas and possibly carbon dioxide and release the doubly charged diimide group. The diimide dianion being chemically unstable decomposes to nitrogen gas.

The gas generating chemicals containing hydrazide groups in which the two nitrogen atoms are connected by a single bond as well as connected to one or two hydrogens produce gas upon reaction with an oxidizing agent. It is believed that the oxidizing agent oxidizes the hydrazide group to azo structure. Therefore, hydrazide materials containing two mutually single bonded nitrogens, which in turn are also bonded to one or more hydrogens, need oxidizing agents for activation. To enhance the water solubility of such materials, alkaline pH is generally required. Occasionally, additional chemicals may be needed to increase the rate of gas production.

Examples of delayed encapsulated activators suitable for use with nitrogen gas generating chemicals include, but are not limited to, alkaline materials such as carbonate, hydroxide and oxide salts of alkali and alkaline earth metals such as lithium, sodium, magnesium and calcium and oxidizing agents such as alkali and alkaline earth metal salts of peroxide, persulfate, perborate, hypochlorite, hypobromite, chlorite, chlorate, iodate, bromate, chloroaurate, arsenate, antimonite and molybdate anions. Specific examples of the oxidizing agents include ammonium persulfate, sodium persulfate, potassium persulfate, sodium chlorite, sodium chlorate, hydrogen peroxide, sodium perborate and sodium peroxy carbonate. Other examples of oxidizers which can be used in the present invention are disclosed in U.S. Pat. No. 5,962,808 issued to Landstrom on Oct. 5, 1999. Of the various activators that can be used, sodium or ammonium persulfate and sodium chlorite are preferred. The actual amounts of the alkaline material used in the well treating fluid should be sufficient to maintain the pH of the fluid between 10 and 14.

Carbon dioxide gas generating chemicals can be selected from the group consisting of organic acids and inorganic acids, and mixtures thereof. Organic acids suitable for use as the gas generating chemical can be selected from the group consisting of carboxylic acids, acetic acids, acetyl salicylic acids, ascorbic acids, citric acids, lactic acids, tartaric acids, gluconic acids, phenyl glycolic acids, benzylic acids, malic acids, salicylic acids, formic acids, propionic acids, butyric acids, oleic acids, linoleic acids, linolenic acids, sorbic acids, benzoic acids, phenyl acetic acids, gallic acids, oxylacetic acids, valeric acids, palmitic acids, fatty acids, valproic acids, acrylic acids, and methacrylic acids, and mixtures thereof, or consisting of any subgroup of the foregoing. Inorganic acids suitable for use as the gas generating chemical can be selected from the group consisting of hydrochloric acids, sulfuric acids, nitric acids, sulfonitric acids, polyphosphoric acids, chlorosulfuric acids, and boric acids, and mixtures thereof, or consisting of any subgroup of the foregoing. Most preferably, the second foam generating agent is 2-hydroxy-1,2,3-propanetricarboxylic acid, citric acid, or mixtures thereof.

Encapsulated activators suitable for use with carbon dioxide gas generating chemicals include, but are not limited to, acid and neutral salts of alkali metals and alkaline earth metals, and mixtures thereof, or consisting of any subgroup of the foregoing. The encapsulated activator can be selected from the group consisting of sodium bicarbonate, potassium bicarbonate, calcium bicarbonate, barium bicarbonate, and lithium bicarbonate, and mixtures thereof, or consisting of any subgroup of the foregoing.

The activators can be encapsulated with various materials which delay their reaction with the gas generating chemical or chemicals used. Solid activators can be encapsulated by spray coating a variety of materials thereon. Such coating materials include, but are not limited to, waxes, drying oils such as tung oil and linseed oil, polyurethanes and cross-linked partially hydrolyzed polyacrylics. Often, because of the oxidizing and corrosive nature of the activators, an additional undercoat of polymeric materials such as styrene butadiene can be deposited on the solid activator particles prior to depositing the slow releasing polymeric coating. Generally, the encapsulating material is chosen so that sufficient release of the activator under the shear conditions at and around the drill tool will be achieved to provide release of sufficient gas to adequately foam the drill-in fluid a predetermined amount.

In general the amount of gas generating chemical and encapsulated activators used in the drill-in fluid will depend on the amount of gas desired and, hence, the amount of foaming desired. The gas generating chemical or chemicals utilized are combined with the well treating fluid in a general amount, depending on the amount of gas desired under downhole conditions, in the range of from about 0.1 percent to about 10 percent by weight of the drill-in fluid. The activator or activators used and their amounts are selected for the activator's ability to cause the gas generating chemical or chemicals to generate gas at a particular temperature or range of temperatures, generally the temperature or range of temperatures at the drill tool. The temperatures at which various activators cause a particular gas generating chemical to produce gas can be readily determined in the laboratory. The amount of the activator included in the well treating fluid in the encapsulated form range from about 0.1 percent to about 10 percent by weight of the drill-in fluid.

In addition to the gas generating chemicals and encapsulated activators, a mixture of foaming and foam stabilizing surfactants can be combined with the drill-in fluid to facilitate the formation and stabilization of the drill-in fluid foam produced by the liberation of gas therein. Generally, these foaming and foam stabilizing surfactants will be present in an amount from 0.01 percent to 10 percent by weight of the drill-in fluid, and can be present in an amount from 0.1 percent to 2 percent by weight of the drill-in fluid. An example of such a mixture of foaming and foam stabilizing surfactants is comprised of an ethoxylated alcohol ether sulfate surfactant, an alkyl or alkene amidopropyl betaine surfactant and an alkyl or alkene amidopropyldimethylamine oxide surfactant. Additional examples of foaming agents include betaines; amine oxides; methyl ester sulfonates; alkylamidobetaines, such as cocoamidopropyl betaine; alpha olefin sulfonate; trimethyltallowammonium chloride; C₈-C₂₂ alkylethoxylate sulfates; and trimethylcocoammonium chloride. Additional examples of foam stabilizers include fatty methyl ester surfactants, aliphatic alkyl sulfonate surfactants, aliphatic alkyl sulfate surfactants, a nanoparticle, and combinations thereof.

A water soluble viscosifier or gelled fluid can be used to adjust the viscosity of the drill-in fluid and/or to help increase foam stability. The viscosifier can be selected from the group consisting of water soluble starches and modified versions thereof, water-soluble polysaccharides and modified versions thereof, water soluble celluloses and modified versions thereof, water soluble polyacrylamides and copolymers thereof, and combinations thereof. Other examples of suitable viscosifiers include biopolymers such as xanthan and succinoglycan, cellulose derivatives such as hydroxyethylcellulose and guar and its derivatives such as hydroxypropyl guar. Water soluble viscosifiers can be present in an amount from about 0.01 percent to about 3 percent by weight of the drill-in fluid.

If used, a variety of fluid loss control additives may be included in the drill-in fluid, including starch, starch ether derivatives, hydroxyethylcellulose, cross-linked hydroxyethylcellulose, and mixtures thereof. In certain preferred embodiments, the fluid loss control additive is starch. The fluid loss control additive is present in the drill-in fluid in an amount sufficient to provide a desired degree of fluid loss control. More particularly, the fluid loss control additive is present in the drill-in fluid in an amount in the range of from about 0.01 percent to about 3 percent by weight.

Bridging agents may optionally be used. Bridging agents are generally solids added to a drilling fluid to bridge across the pore throat or fractures of an exposed rock thereby preventing loss of drilling fluid or excessive filtrate. Fluid loss control additives and bridging agents achieve a somewhat similar result; however, generally fluid loss control additives form a seal or filter cake to seal off the flow channel or path into the surrounding reservoir or rock without any substantial penetration and bridging materials have some degree of invasion or penetration into the pore space to mechanically bridge off or seal the reservoir or rock. Bridging materials are commonly used in drilling fluids and in lost circulation treatments. For reservoir applications, the bridging agent should be removable. Common products include calcium carbonate (acid-soluble), suspended salt (water-soluble) or oil-soluble resins. For lost circulation treatments, any suitably sized products can be used, including mica, nutshells and fibers. These products are also referred to as lost circulation material (LCM).

If used, the bridging agent can comprise solid particulates or a degradable material and can be present in the drill-in fluid in an amount sufficient to create an efficient filter cake. In certain embodiments, the bridging agent comprised of the degradable material is present in the well drill-in fluid in an amount ranging from about 0.1 percent to about 3 percent by weight. Examples of solid particulates to be used as bridging agent include latex polymer, graphite, calcium carbonate, dolomite, celluloses, micas, sand or ceramic particles. The degradable material comprises a degradable polymer or a dehydrated compound. Examples of the degradable polymer include polysaccharides, chitins, chitosans, proteins, orthoesters, aliphatic polyesters, poly(glycolides), poly(lactides), poly(ε-caprolactones), poly(hydroxybutyrates), polyanhydrides, aliphatic polycarbonates, poly(orthoesters), poly(amino acids), poly(ethylene oxides), or polyphosphazenes. Examples of the dehydrated compound include anhydrous sodium tetraborate or anhydrous boric acid.

Thus, a method in accordance with one embodiment of the invention starts with providing a drill-in fluid comprising an aqueous fluid, a foaming agent, a foam stabilizer, a gas generating chemical and an encapsulated activator. As mentioned above, the drill-in fluid can have other components such as fluid loss control agents, bridging agents and/or viscosifying agents; however, it is an advantage of the invention that the need for such additional agents is reduced or eliminated. Accordingly, in another embodiment the drill-in fluid provided consists essentially of an aqueous fluid, a foaming agent, a foam stabilizer, a gas generating chemical and an encapsulated activator and the method in accordance with the invention does not rely on any substantial amounts of additional fluid loss control agents, bridging agents and/or viscosifying agents.

After an aqueous fluid, a foaming agent, a foam stabilizer, a gas generating chemical and an encapsulated activator have been combined to produce the drill-in fluid, the drill-in fluid is introduced downhole into and through a drill string connected at its downhole end to a drill tool. Accordingly, both the gas generating chemical and the encapsulated activator are admixed into the drill-in fluid prior to introduction into the drill string. While one or the other of the gas generating and encapsulated activator can be introduced into the drill-in fluid after the rest of the drill-in fluid has been introduced downhole, this would eliminate several advantages of the current invention and increase cost associated with the use of the drill-in fluid. For example, admixing the encapsulated activator downhole just prior to the drill tool would require a separate stream for the encapsulated activator and increase the cost and amount of equipment needed . The current invention does not need such separate streams for the components of the drill-in fluid; rather, all the components can be admixed at the surface and introduced into the drill string together.

When the drill-in fluid reaches the drill tool it flows through the drill tool and exits into the wellbore (or borehole) in the region between the borehole wall and the drill tool. The drill tool can be most common types of downhole drill tools, such as a drill bit or jet drill. Drill bits or rotary drills are conventional drill tools that use teeth on the drill head to crush or grind up rock. Generally, drill bits are hollow and have jets to allow for the expulsion of drilling fluid. The operation of the drill bit causes high shear regions within the hollow interior of the drill bit, at the jets and teeth of the drill bit and in the region outside the drill bit between the borehole wall and the drill bit where the drilling action is occurring to grind or drill rock or other substances. Thus, upon exiting the drill bit, the encapsulated activator is de-capsulated or released by shearing action sufficiently to react with the gas generating chemical such that a gas is generated within the drill-in fluid and thus foams the drill-in fluid at the drill bit teeth and between the drill bit and the borehole wall. While it is within the scope of the invention for all or part of the de-capsulation to occur by a delayed encapsulation in which temperature or time of exposure to other compounds, such as the aqueous fluid, result in de-capsulation or release of the activator, such embodiments are subject to timing miscalculations and can result in the foaming of the drill-in fluid prior to reaching the drill bit or after the drill-in fluid has moved uphole from the region between the drill bit and the borehole. Accordingly, it is preferred that the de-capsulation be performed by the shearing action at and around the drill bit.

“Jet drills” as used herein is used to refer to both conventional jet drills and hydrajets, unless otherwise indicated. Such jet drills release or jet a fluid through nozzles on the drill head, thus creating a high-velocity stream of fluid. Hydrajets use a fluid, typically an aqueous fluid, carrying small abrasive particles. The high-velocity or high pressure abrasive carrying fluid erodes or abrades away the rock. Conventional jet drills typically use drill-in fluid without added abrasives for the high-velocity stream. In the current invention, the drill-in fluid described above can be used with or without abrasives in hydrajet or conventional jet drilling tools. In both hydrajet and conventional jet drilling tools there are high shear conditions at the nozzles and in the region outside the jet drill between the borehole wall and the jet drill where the drilling action is occurring to abrade or erode rock or other substances. Thus, upon exiting the jet drill the encapsulated activator is de-capsulated or released by shearing action sufficiently to react with the gas generating chemical such that a gas is generated within the drill-in fluid and thus foams the drill-in fluid between the jet drill and the borehole wall.

After the drill-in fluid exits the drill tool, the thus created foamed drill-in fluid is circulated around the region between the drill tool and the borehole wall; thus cooling and lubricating the drill tool (typically with drill bits) and entraining drill cuttings into the foamed drill-in fluid. The drill-in fluid is further circulated into an annulus formed between the wellbore and the drill string such that drill cuttings produced during drilling are carried by the foamed drill-in fluid back to the surface via the annulus. The foamed drill-in fluid is recovered from the annulus, generally at the surface and the foamed drill-in fluid is then defoamed to form a defoamed drill-in fluid. Generally, to improve economics and efficiency, the drill-in fluid will be reused. Accordingly, the drill cuttings and other impurities can be removed from the drill-in fluid before, during or after defoaming. Subsequently, the defoamed and clean drill-in fluid will be admixed with additional amounts of the gas generating agent and additional amounts of the encapsulated activator to replace these components that were used downhole. The thus formed recirculation drill-in fluid is re-introduced into the drill string to thus repeat the use of the drill-in fluid as described above. Generally, the drill-in fluid will be recycled downhole many times with some fresh drill-in fluid added as necessary to make up for drill-in fluid lost during the operation.

EXAMPLE

The following prophetic example illustrates the use of one embodiment of the inventive drill-in fluid in association with an oil well drilling process.

First, fresh water, potassium chloride (a clay stabilizer), cocoamidopropyl betaine (a foaming agent), an alkyl amidopropyldimethylamine oxide surfactant (a foam stabilizer), azodicarbonamide (a nitrogen gas generating chemical), and ammonium persulfate encapsulated with polyurethane (an encapsulated activator) are mixed together on the surface at a well site to produce a drill-in fluid at the well site. The drill-in fluid comprises approximately 92 percent by weight of the aqueous fluid, approximately 1.0 percent by weight of the foaming agent, approximately 4.0 percent by weight of the gas generating chemical and approximately 3.0 percent by weight of encapsulated activator.

The drill-in fluid is then introduced downhole into and through a drill string penetrating the well bore and connected at its downhole end to a jet drill. As the drill-in fluid reaches the jet drill it flows through the hollow interior of the jet drill and through the jets on the end of the jet drill where it exits into the wellbore (or borehole) in the region between the borehole wall and the jet drill. As the drill-in fluid exits the jet drill, the encapsulated activator is de-capsulated by shearing action sufficiently to react with the gas generating chemical such that a gas is generated within the drill-in fluid and thus foams the drill-in fluid at the jet drill teeth and between the jet drill and the borehole wall.

After the drill-in fluid exits the jet drill, the thus created foamed drill-in fluid is circulated around the region between the jet drill and the borehole wall; thus cooling and lubricating the jet drill and entraining drill cuttings into the foamed drill-in fluid. The drill-in fluid is further circulated into an annulus formed between the wellbore and the drill string such that drill cuttings produced during drilling are carried by the foamed drill-in fluid back to the surface via the annulus. The foamed drill-in fluid is recovered from the annulus at the surface and the foamed drill-in fluid is then defoamed to form a defoamed drill-in fluid. The drill cuttings and other impurities are removed from the drill-in fluid after the fluid is defoamed. The defoamed drill-in fluid is then recycled (by addition additional amounts of the gas generating agent and encapsulated activator) and recirculated into the drill string where it is again used as described above. The drill-in fluid is successfully recycled downhole many times.

It will be seen that the method of the current invention is well adapted to carry out the ends and advantages mentioned as well as those inherent therein. While the presently preferred embodiment of the invention has been shown for the purposes of this disclosure, numerous changes in the arrangement and construction of parts may be made by those skilled in the art. All such changes are encompassed within the scope and spirit of the dependent claims. 

What is claimed is:
 1. A method of drilling in a wellbore comprising: a. providing a drill-in fluid comprising an aqueous fluid, a foaming agent, a foam stabilizer, a gas generating chemical and an encapsulated activator; b. introducing said drill-in fluid downhole into a drill string connected to a drill tool wherein both said gas generating chemical and said encapsulated activator are admixed into said drill-in fluid prior to introduction into said drill string; and c. allowing said drill-in fluid to exit said drill tool where, upon exiting said drill tool, said encapsulated activator is de-capsulated sufficiently to react with said gas generating chemical such that a gas is generated within said drill-in fluid and thus foams said drill-in fluid.
 2. The method of claim 1, wherein said method further comprises the steps of: d. circulating the thus formed foamed drill-in fluid into an annulus formed between said wellbore and said drill string; and e. recovering said foamed drill-in fluid from said annulus.
 3. The method of claim 2, wherein step d further comprises circulating such that drill cuttings produced during drilling are carried by said foamed drill-in fluid back to the surface via said annulus and wherein said foamed drill-in fluid is recovered at the surface in step e.
 4. The method of claim 3, wherein said method further comprises the steps of: f. defoaming said thus recovered foamed drill-in fluid to form a defoamed drill-in fluid; g. admixing said defoamed drill-in fluid with additional amounts of said gas generating agent and additional amounts of said encapsulated activator to form a recirculation drill-in fluid; and h. recirculating said recirculation drill-in fluid downhole into said drill string to thus repeat steps b through e for said recirculation drill-in fluid.
 5. The method of claim 1, wherein said drill-in fluid further comprises one or more of a water soluble viscosifier, a fluid loss control additive and a bridging agent.
 6. The method of claim 1, wherein the method does not use a bridging agent.
 7. The method of claim 1, wherein the method does not use a fluid loss control additive.
 8. The method of claim 1, wherein the method does not use a water soluble vicosifier.
 9. The method of claim 1, wherein the method is carried out without the use of viscosifiers, fluid loss control additives and bridging agents other than as those functions are carried out by one or more of said aqueous fluid, said foaming agent, said foam stabilizer, said gas generating chemical and said encapsulated activator as present in said foamed drill-in fluid.
 10. The method of claim 1 wherein said drill tool is a drill bit and said encapsulated activator is de-capsulated by shearing action upon passing through said drill bit.
 11. The method of claim 1 wherein said drill tool is a jet drill having a nozzle and said encapsulated activator is de-capsulated by shearing action upon passing through said nozzle.
 12. The method of claim 1 wherein said encapsulated activator has a selected release time such that it de-capsulates at said drill tool.
 13. The method of claim 1 wherein said drill-in fluid is foamed downhole between said drill tool and said borehole.
 14. The method of claim 1 wherein said aqueous solvent is an aqueous brine.
 15. A method of drilling in a wellbore comprising: a. providing a drill-in fluid comprising an aqueous brine, a foaming agent, a foam stabilizer, a gas generating chemical and an encapsulated activator; b. introducing said drill-in fluid downhole into a drill string connected to a drill tool wherein both said gas generating chemical and said encapsulated activator are admixed into said drill-in fluid prior to introduction into said drill string; c. allowing said drill-in fluid to exit said drill tool where, upon exiting said drill tool, said encapsulated activator is de-capsulated by shearing action sufficiently to react with said gas generating chemical such that a gas is generated within said drill-in fluid and thus foams said drill-in fluid between said drill tool and said borehole; d. circulating the thus formed foamed drill-in fluid into an annulus formed between said wellbore and said drill string such that drill cuttings produced during drilling are carried by said foamed drill-in fluid back to the surface via said annulus; e. recovering said foamed drill-in fluid from said annulus at the surface; f. defoaming said thus recovered foamed drill-in fluid to form a defoamed drill-in fluid; g. admixing said defoamed drill-in fluid with additional amounts of said gas generating agent and additional amounts of said encapsulated activator to form a recirculation drill-in fluid; and h. recirculating said recirculation drill-in fluid downhole into said drill string to thus repeat steps b through e for said recirculation drill-in fluid.
 16. The method of claim 15, wherein said drill-in fluid further comprises one or more of a water soluble viscosifier, a fluid loss control additive and a bridging agent.
 17. The method of claim 15, wherein the method is carried out without the use of viscosifiers, fluid loss control additives and bridging agents other than as those functions are carried out by one or more of said aqueous fluid, said foaming agent, said foam stabilizer, said gas generating chemical and said encapsulated activator as present in said foamed drill-in fluid.
 18. A method of drilling in a wellbore comprising: a. providing a drill-in fluid consisting essentially of an aqueous fluid, a foaming agent, a foam stabilizer, a gas generating chemical and an encapsulated activator; b. introducing said drill-in fluid downhole into a drill string connected to a drill tool wherein said aqueous fluid, said foaming agent, said foam stabilizer, said gas generating chemical and said encapsulated activator are admixed into said drill-in fluid prior to introduction into said drill string; and c. allowing said drill-in fluid to exit said drill tool where, upon exiting said drill tool, said encapsulated activator is de-capsulated sufficiently to react with said gas generating chemical such that a gas is generated within said drill-in fluid and thus foams said drill-in fluid and wherein said drilling is carried out without the use of viscosifiers, fluid loss control additives and bridging agents other than as those functions are carried out by one or more of said aqueous fluid, said foaming agent, said foam stabilizer, said gas generating chemical and said encapsulated activator as present in said thus foamed drill-in fluid.
 19. The method of claim 18 wherein said encapsulated activator is de-capsulated by shearing action upon passing through said drill tool. 